Not infrequently, the Commission amends a conservation order that prescribes pool rules for a specific pool. For ease of reference and to minimize confusion, it has been the Commission’s recent practice to incorporate such amendments from time to time in a comprehensively revised version of the underlying conservation order that supersedes and replaces the previous version of the order. This ensures that all applicable pool rules are set out in a single document and avoids the necessity of reviewing multiple orders relating to a single pool.

On June 25, 2004, the Commission issued such a comprehensively revised order prescribing pool rules for the Aurora Oil Pool, in the form of Conservation Order No. 457B. One of the sources of amendments to the previous version of this order was Conservation Order No. 492, which established rules governing sustained annulus pressures for all pools within the Prudhoe Bay Field, including the Aurora Oil Pool. Conservation Order No. 457B stated that it “supersedes and replaces CO 457 dated September 7, 2001, CO 457A dated May 15, 2003, and CO 492 dated June 26, 2003.” Since CO 492 affects other pools in the Prudhoe Bay field in addition to the Aurora Oil Pool, this statement is not correct. Conservation Order No. 457B supersedes and replaces CO 492 only insofar as CO 492 concerns the Aurora Oil Pool. Conservation Order No. 457B has no effect on CO 492 as to any other pools.

Conservation Order No. 457B has been corrected accordingly. A copy of the corrected version is attached.

Sincerely,

John K. Norman
Chairman

Re:

THE APPLICATION OF BPXA EXPLORATION (ALASKA) INC. for an order expanding the affected area of the Aurora Oil Pool, Prudhoe Bay Field, North Slope, Alaska

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Conservation Order No. 457B

Prudhoe Bay Field
Aurora Oil Pool

June 25, 2004
Corrected August 9, 2004

IT APPEARING THAT:

1. BP Exploration (Alaska), Inc. (“BPXA”) by application dated March 26, 2004, applied for expansion of the affected area for the Aurora Oil Pool (“AOP”) rules as defined in Conservation Order (“CO”) No. 457A;

2. BPXA provided supplemental information at the Commission’s request on April 12, 2004;

3. Notice of a public hearing, tentatively scheduled for May 6, 2004, was duly published in the Anchorage Daily News on April 2, 2004; and

4. No requests for hearing or objections concerning the application were received.

FINDINGS:

1. CO 457A defines the AOP and sets out rules governing its development and operation within a specified area.

2. BPXA proposes to expand the operation and development of the pool beyond the area specified in CO 457A.

3. Subsurface wireline log data, pressure measurements, and newly reprocessed seismic data all indicate that the AOP extends beyond the area specified in CO 457A to encompass the additional area proposed for development.

4. No reason appears why the rules set out in CO 457A should not also apply to operation and development of the AOP in the additional area proposed for development.

5. CO 492 establishes requirements for managing annular pressures for all pools within the Prudhoe Bay Field, including the AOP. No reason appears why the requirements established in CO 492 should not be integrated into a single conservation order governing the AOP.

6. Administrative Approval (“AA”) 457A.01 was issued to clarify requirements for maximum allowable annular pressure. No reason appears why the provisions of this Administrative Approval should not be integrated into a single conservation order governing the AOP.

7. AA 457A.02 permanently approved the use of the Prudhoe Bay Unit Western Satellite Production Metering Plan for production allocation and set out reporting requirements under this plan. No reason appears why the provisions of this Administrative Approval should not be integrated into a single conservation order governing the AOP.

CONCLUSIONS:

1. The area subject to pool rules governing the development and operation of the AOP should be expanded to encompass the additional area proposed for development and indicated by subsurface well data, newly reprocessed seismic data, and reservoir pressure data acquired to date as being within the AOP.

2. All rules and approvals issued by the Commission for AOP operation and development should be consolidated into a single conservation order.

3. The record for this order includes the hearing records and administrative files related to Conservation Orders 457, 457A and 492 including administrative approvals issued under those orders.

NOW, THEREFORE, IT IS ORDERED:

This Conservation Order supersedes and replaces CO 457 dated September 7, 2001, CO 457A dated May 15, 2003, and – as to the Aurora Oil Pool only – CO 492 dated June 26, 2003. The findings, conclusions and administrative record for Conservation Orders 457, 457A and 492 are adopted by reference and incorporated in this decision. The following rules, in addition to statewide requirements under 20 AAC 25, to the extent not superseded by these rules, apply to the Aurora Oil Pool within the following affected area:

Spacing units within the pool shall be a minimum of 40 acres. 20 AAC 25.055(a)(1) and (2) shall not apply to property lines within the external boundaries of the Aurora Participating Area.

Rule 2. Casing and Cementing Practices (CO457, 9/7/01)

In addition to the requirements of 20 AAC 25.030, the conductor casing must be set at least 75 feet below the surface.

In addition to the requirements of 20 AAC 25.030, the surface casing must be set at least 500 feet tvdss below the permafrost.

Rule 3. Automatic Shut-in Equipment (CO457, 9/7/01)

All wells must be equipped with a fail-safe automatic surface safety valve system capable of detecting and preventing an uncontrolled flow.

All wells must be equipped with a landing nipple at a depth below permafrost, which is suitable for the future installation of a downhole flow control device to control subsurface flow. The Commission may require such installation by administrative action.

Safety valve systems must be maintained in good working order at all times and must be tested a minimum of once each six months or according to such other schedule as is prescribed by the Commission.

The PBU Western Satellite Production Metering Plan, approved by the Commission in CO 471 effective August 1, 2002 governs satellite production within the Western Operating Area of the Prudhoe Bay Unit, including the Aurora Oil Pool.

The Prudhoe Bay Unit Gathering Center 2 well allocation factor for oil, gas, and water shall be applied to adjust total AOP production.

All wells must be tested a minimum of once per month. All new AOP wells must be tested a minimum of two times per month during the first three months of production. The Commission may require more frequent or longer tests if the allocation quality deteriorates.

Technical process review meetings with the Commission shall be held at least annually.

The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for the Commission’s review and evaluation.

Rule 5. Reservoir Pressure Monitoring (CO457, 9/7/01)

Prior to regular production or injection, an initial pressure survey shall be performed in each well.

The minimum number of bottom-hole pressure surveys performed each year shall equal the number of governmental sections within the AOP that contain active wells. A minimum of four such surveys shall be conducted each year in representative areas of the AOP. Bottom-hole surveys conducted pursuant to paragraph “a” of this Rule may be used to fulfill the minimum requirement.

Data and results from all reservoir pressure monitoring tests on surveys must be reported to the Commission quarterly on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412, but shall be available for inspection by the Commission upon request.

Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph “e” of this Rule.

Rule 6. Gas-Oil Ratio Exemption (CO457, 9/7/01)

Wells producing from the AOP are exempt from the gas-oil-ratio limits of 20 AAC 25.240 (a) so long as the requirements of 20 AAC 25.240 (b) are met.

Water and enriched hydrocarbon gas injection are authorized to enhance oil recovery within the AOP. Average reservoir pressure must be maintained above minimum miscibility pressure. Expansion of miscible gas injection outside of the North of Crest and West Blocks must be administratively approved by the Commission prior to long-term injection. Commission approval is required prior to implementing major changes in reservoir depletion strategy.

An annual reservoir surveillance report for the prior calendar year shall be filed with the Commission after one year of regular production and annually thereafter. The report shall include, but is not limited to, the following:

Voidage balance by month of produced fluids and injected fluids and cumulative status by major fault blocks;

Summary and analysis of reservoir pressure surveys within the pool;

Results, and where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring;

Review of pool production allocation factors and issues over the prior year; and

Review of the Annual Plan of Operations and Development including discussion of the reservoir depletion plan and the current status of reservoir repressurization activity.

Rule 9. Production Anomalies (CO457, 9/7/01)

In the event of oil production capacity proration at or from the Prudhoe Bay Unit facilities, all commingled reservoirs produced through the Prudhoe Bay Unit facilities shall be prorated by an equivalent percentage of oil production, unless it is determined by the Commission that this will result in surface or subsurface equipment damage.

Rule 10. Administrative Action (CO457, 9/7/01)

Upon proper application or its own motion, the Commission may administratively waive the requirements of any rule stated above or administratively amend this Order as long as the change does not promote waste or jeopardize correlative rights, and is based on sound engineering and geoscience principles.

The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety.

The operator shall monitor each development well daily to check for sustained pressure, unless prevented from doing so by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection.

The operator shall notify the AOGCC within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2000 psig or (ii) sustained outer annulus pressure that exceeds 1000 psig.

The Commission may require the operator to submit in an Application for Sundry Approvals (Form 10-403), a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph c. of this rule. The Commission may approve the operator’s proposal or may require other corrective action or surveillance. The Commission may require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests.

If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well’s production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well’s surface casing for outer annulus pressure, the operator shall immediately notify the Commission and take corrective action. Unless well conditions require the operator to take emergency corrective action before Commission approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The Commission may approve the operator’s proposal or may require other corrective action. The Commission may also require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests.

Except as otherwise approved by the AOGCC under paragraph “d” or “e” of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree that (i) the inner annulus pressure at operating temperature will be below 2000 psig, and (ii) the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph “c”, but not paragraph “e”, of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph “c”, unless the AOGCC prescribes a different limit.

Rule 12. Definitions

For purposes of these rules;

“inner annulus” means the space in a well between tubing and production casing;

“outer annulus” means the space in a well between production casing and surface casing;

“sustained pressure” means pressure that (i) is measurable at the casing head of an annulus, (ii) is not caused solely by temperature fluctuations, and (iii) is not pressure that has been applied intentionally.

DONE at Anchorage, Alaska and dated June 25, 2004.
Corrected August 9, 2004